Use of Oil-in-water Pickering Emulsion Stabilized by Nanoparticles in Combination With Polymer Flood for Enhanced Oil Recovery

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1 Petroleum Science and Technology ISSN: (Print) (Online) Journal homepage: Use of Oil-in-water Pickering Emulsion Stabilized by Nanoparticles in Combination With Polymer Flood for Enhanced Oil Recovery T. Sharma, N. Velmurugan, P. Patel, B. H. Chon & J. S. Sangwai To cite this article: T. Sharma, N. Velmurugan, P. Patel, B. H. Chon & J. S. Sangwai (2015) Use of Oil-in-water Pickering Emulsion Stabilized by Nanoparticles in Combination With Polymer Flood for Enhanced Oil Recovery, Petroleum Science and Technology, 33:17-18, To link to this article: Published online: 08 Dec Submit your article to this journal View related articles View Crossmark data Full Terms & Conditions of access and use can be found at Download by: [Inha University] Date: 08 December 2015, At: 18:40

2 Petroleum Science and Technology, 33: , 2015 Copyright C Taylor & Francis Group, LLC ISSN: print / online DOI: / Use of Oil-in-water Pickering Emulsion Stabilized by Nanoparticles in Combination With Polymer Flood for Enhanced Oil Recovery T. Sharma, 1,2,3 N. Velmurugan, 3,4 P. Patel, 3 B. H. Chon, 5 and J. S. Sangwai 1 1 Enhanced Oil Recovery Laboratory, Department of Ocean Engineering, Indian Institute of Technology Madras, Chennai, India 2 Department of Petroleum Engineering, Rajiv Gandhi Institute of Petroleum Technology, Rae Bareli, India 3 School of Petroleum Technology, Pandit Deendayal Petroleum University, Gandhinagar, India 4 Department of Petroleum Engineering and Applied Geophysics, Norwegian University of Science and Technology, Trondheim, Norway 5 Department of Energy Resources Engineering, Inha University, Incheon, South Korea Efficient flooding agents are required to produce additional oil from mature reservoir. In this work, oil-in-water Pickering emulsion systems stabilized using nanoparticles, surfactant, and polymer have been developed and tested for enhanced oil recovery with and without a conventional polymer flood. Stability of nanoparticles in the dispersion of surfactant-polymer solution was tested using zeta-potential before use. Several flooding experiments have been conducted using Berea core samples at 13.6 MPa and temperatures of 313 and 353 K. It has been observed that a combination of 0.5 PV polymer flood with 0.5 PV Pickering emulsion was efficient and have resulted in 1 6% additional oil recovery as compared to 0.5 PV Pickering emulsion flooding alone. The injection of polymer flood have shown to enhance the pressure drop in the core sample after emulsion flooding and considered as an important factor for an additional recovery of oil. The effect of temperature on the viscosity of flooding agents in relation to pressure drop and oil recovery have also been investigated. Viscosity and pressure drop of emulsion flood systems have shown to marginally decrease with increase in temperature. Studies on nanoparticle retention using SEM have shown that nanoparticles were retained in the core sample during emulsion flooding which may be detrimental for permeability of core sample. It is observed that Pickering emulsion flood with polymer flood would be effective for the enhanced oil recovery suitable for matured reservoirs. Keywords: enhanced oil recovery, nanoparticle, Pickering emulsion, polymer, surfactant 1. INTRODUCTION Emulsion flooding is a potential chemical enhanced oil recovery process for production of additional oil after water flooding. The process leads to several interactions with reservoir fluids to improve Address correspondence to J. S. Sangwai, Enhanced Oil Recovery Laboratory, Department of Ocean Engineering, Indian Institute of Technology Madras, Chennai , India. jitendrasangwai@iitm.ac.in Color versions of one or more of the figures in the article can be found online at

3 1596 T. SHARMA ET AL. properties such as viscous fingering, fractional flow, and sweep efficiency to mobilize the crude oil in the reservoir (Hermansen et al., 2000). Ideally, stable emulsions are formed from oil and water using different emulsifiers such as surfactant, polymer, and nanoparticles (Sharma et al., 2014). However, the use of emulsions stabilized by conventional emulsifiers may show significant degradation in the stability at elevated temperature. Emulsions stabilized by nanoparticles may improve the rate of resultant oil recovery by providing superior stability against hostile reservoir conditions (Sarma et al., 1998; Sharma et al., 2015). It has been observed that nanoparticle can reduce the extent of emulsion destabilization as compared to classical emulsifiers to make them a suitable candidate for high-pressure high-temperature (HPHT) oilfield practices (Zhang et al., 2010). Recently, it has been concluded that stable nanofluids can be designed using nanoparticle with a viscosifier such as xanthan gum (Ponmani et al., 2014) suitable for HPHT oilfield applications. In EOR, flooding agent is typically followed by the injection of a chase water flood to drive it along with oil toward production well. However, the chase water has less viscosity and the direct use of it after a viscous emulsion flood may show viscous fingering due to mobility contrast leaving significant emulsion and oil in the reservoir pores (Sarma et al., 1998). This aspect need to be addressed for not only improving the recovery of oil, but also the recovery of emulsion which is being used as flooding agent into the reservoir. Several water-soluble polymers have been explored as viscosifier for various oilfield applications such as EOR, drilling fluid design, water shutoff, and plugging jobs (Lee, 2010; Hematpour et al., 2011). Though, several studies have investigated the use of polymer and polymer-based solutions for oil recovery, none of these studies aimed at investigating the effect of a polymer flood on tertiary oil recovery using Pickering emulsion stabilized by nanoparticle-surfactant-polymer (NSP) system. In our previous work, we demonstrated the use of water soluble polymer polyacrylamide (PAM) on the formation of thermally stable o/w Pickering emulsion stabilized by NSP system (Sharma et al., 2014). Recently, we also reported results of several core-flood experiments using these emulsions at 13.6 MPa and different temperatures (Sharma et al., 2015). In this study, we have extended the scope of previous study by using a polymer flood along with these emulsions to analyze further improvement in oil recovery, which has not been reported in the literature. In this work, several core-flood experiments have been performed at confining pressure of 13.6 MPa and temperature of 313 and 353 K. Emulsifiers used in this study are polymer PAM, surfactant sodium dodecylsulfate (SDS) and nanoparticles, viz. hydrophilic SiO 2 ( 15 nm diameter) and partially hydrophobic clay (<80 nm diameter). 2. EXPERIMENTAL 2.1 Materials The oil used for the preparation of emulsion, polymer PAM (molecular weight of 10 7 g/mol), SDS, and nanoparticles were obtained from various suppliers (Sharma et al., 2014). Flooding experiments were performed with a crude oil (viscosity 161 mpa.sec and 33 API gravity) collected from an oilfield near Ahmedabad, Gujarat, India (Sharma et al., 2015). For pre-flush and chase water flood experiments, brine with salinity of 36,100 mg/l was used and prepared using deionized water and salt, NaCl of reagent grade (Sharma et al., 2015). A weighing balance (Reptech RA-1012 with a repeatability of ± mass fraction) and a homogenizer (Remi RQT-127/D) with mixing speed ranges from 300 to 6000 rpm, were used to prepare all the aqueous solutions. 2.2 Preparation of Polymer and Emulsion Samples First, a polymer solution of 1000 ppm was prepared by mixing PAM in deionized water using homogenizer rotated at 1000 rpm until complete dissolution. The same polymer solution was used

4 USE OF OIL-IN-WATER PICKERING EMULSION 1597 FIGURE 1 Core-flood experimental setup and its units. as polymer flood for core-flood experiments after NSP emulsion flood. Thereafter, surfactant mixture of a conventional detergent and SDS (0.22 wt%) in the ratio of 57:43, respectively was mixed into PAM solution. Nanoparticles, viz. SiO 2 and clay of 1.0 wt%, were mixed in above solution to check dispersion stability using zeta potential studies. Once the dispersion of nanoparticle was ensured, NSP emulsion was prepared by mixing oil (volume fraction 0.25) in the solution. Nanoparticle concentration was kept constant as 1.0 wt% throughout the study. 2.3 Characterization of Samples Microscopic characterization of NSP emulsion was performed using a microscope (Motic microscope, Hong Kong). Size distribution was determined by a particle size analyzer (Zetasizer Nano-S90, Malvern Instruments, England) working on DLS (dynamic light scattering) technique. The viscosity of flood systems was measured at shear rate of 1.0 sec 1 and temperature of 313 and 353 K using a compact rheometer MCR-52 (Anton Paar, Physica, Austria). Nanoparticle retention in core samples was examined through a high-resolution scanning electron microscope (FEG 200, Quanta SEM, USA). For this purpose, one of the post-flood core samples was used. A small fragment of dimension around cm was sliced from that core and gold coated to analyze for SEM investigation. Zeta potential measurements of nanoparticles were performed using a zetasizer (Nano Z, Malvern Instruments, England) based on laser Doppler microelectrophoresis technique. 2.4 Flooding Apparatus and Procedure The setup used for flooding experiments (as shown in Figure 1) contains a hydrostatic core holder (Vinci Technologies, France), syringe pump (Teledyne Isco, USA), and fluid accumulators. Core samples were cylindrical in size with a diameter of 3.81 cm and length 8.70 cm and represented closely with a porous and permeable reservoir rock Berea sandstone (Sharma et al., 2015). First, dry core sample was flooded with brine for certain period of time at test temperature (313 and 353 K, separately) with a constant injection rate of 20 ml/h until 100% saturation was achieved (Sharma et al., 2015). Core sample was then flooded with crude oil at 20 ml/h until consistent

5 1598 T. SHARMA ET AL. TABLE 1 Properties of Berea core used for core-flood experiments Effective Permeability, md Core Dimension, cm CS Experiment No. Pore volume, ml Porosity,% S oi,% S wi,% k w, S w = 1 k o, S wi D = 3.81 and L = D = diameter of the core, L = length of the core; S oi = initial oil saturation; S wi = irreducible water saturation; CS = core sample. oil drops were received at the outlet end of core (Figure 1). This condition of the core sample represents initial condition of the reservoir suitable for water flood and chemical-eor. This stage provides information on initial oil and water saturation. Subsequently, it was then followed by the injection of brine to analyze and record the oil recovery under secondary recovery (water flooding). The core was now flooded with NSP emulsion with injection volume of 0.5 pore volume (PV) and oil recovery was recorded. The next flooding was performed with and without the injection of viscous polymer solution (of 0.50 PV) as a mobility control agent followed by 2 PV of brine under chase water flooding. The above overall experimental procedure followed is to closely mimic the actual reservoir production behavior under secondary and tertiary (chemical)- EOR processes. Various parameters such as, porosity, permeability, pore volume, irreducible water saturation (S wi ), and initial oil saturation (S oi ) were also measured systematically and given in Table RESULTS AND DISCUSSION 3.1 Measurements of Emulsion Properties Figure 2A shows the zeta potential of nanoparticles in dispersion stabilized by NSP system (no emulsion). Zeta potential of dispersions was observed to be 36.9 (SiO 2 ) and 40.3 mv (clay). As the zeta potential is less than 30 mv for both the dispersions, this shows that the nanoparticles are strongly repelled in the medium indicating good dispersion stability. Once the dispersion of nanoparticle in NSP system is verified, o/w emulsion was prepared by dispersion of oil into NSP solution (as discussed in procedure). To analyze creaming stability, SiO 2 and clay stabilized NSP emulsions were kept in transparent vessels for few days. Emulsions were found to be stable against creaming for more than three weeks; around 23 days (Sharma et al., 2014). Figure 2B shows microscopic images of these emulsions at 298 K. The oil droplets are observed to be smaller and varying in size, however, densely dispersed. The average size of droplets was determined to be around 2.16 and 3.65 µm for SiO 2 and clay NSP emulsions, respectively (Sharma et al., 2015).

6 USE OF OIL-IN-WATER PICKERING EMULSION 1599 FIGURE 2 (A) Zeta potential measurements and (B) microscopic images of NSP-based dispersions and emulsions, respectively, prepared using 1.0 wt% nanoparticles, 0.22 wt% surfactant, and 1000 ppm polymer at 298 K. 3.2 Viscosity Measurement The viscosity of samples was measured at the shear rate of 1.0 sec 1 and test temperature of 313 and 353 K. Emulsion samples were gently shaken before viscosity measurement and repeated at least thrice to check the reproducibility. The viscosity of 1000 ppm polymer solution decreased with increasing temperature from 0.73 (313 K) to 0.35 Pa.sec (353 K). The viscosity was observed to be 0.26 (313 K) and 0.18 Pa.sec (353 K) for SiO 2 emulsion, while it was 0.17 (313 K) and 0.14 Pa.sec (353 K) for clay emulsion (Sharma et al., 2015). It is to be noted here that the viscosity of emulsion did not decrease significantly with increase in temperature. The reason may be attributed to the presence of nanoparticle restrictive barrier, which sterically hindered the emulsion deformation against temperature (Sharma et al., 2014). 3.3 Core Flooding Tests In this study, the effect of polymer flood on core-flood results of NSP emulsion flooding are represented by pressure drop and oil recovery experiments. Pressure drop was monitored carefully from the injection of brine to the termination of chase water flood. Core-flood process starts from the initial condition of core sample (see experimental procedure) with the injection of 2.0 PV of brine (water flooding) followed by 0.5 PV of SiO 2 and clay NSP emulsion with and without 0.50 PV of

7 1600 T. SHARMA ET AL. polymer flood, which finally ends with 2.0 PV of chase water. Figure 3A compares the results on pressure drop obtained using the combination of Pickering emulsion and polymer flood together and only Pickering emulsion flood (Sharma et al., 2015). As shown in Figure 3A-i, at 313 K, pressure drop remained around 0.09 MPa during brine injection and increased to 0.38 (SiO 2 ; experiment no. 1) and 0.35 MPa (clay; experiment no. 2) during emulsion flooding (Sharma et al., 2015). This is likely due to higher viscosity of injected emulsion than brine (Pei et al., 2012). Pressure drop decreased and stabilized to 0.09 MPa after chase water flood. For experiment no. 3 and 4, at 313 K, emulsion flood is followed by the injection of a polymer flood of 0.50 PV before using chase water flood. The use of viscous polymer flood during experiment nos. 3 (SiO 2 ) and 4 (clay) kept pressure drop higher inside core for around 0.8 PV before reaching to 0.09 MPa after chase water flood (Figure 3A-iii). Higher pressure drop indicates that the flood agent is moving uniformly within the pores of the cores, reducing viscous fingering, and resulting in higher oil recovery. Therefore, it is expected that the use of polymer flood after Pickering emulsion flood is expected to produce more oil as compared to oil recovered during experiment nos. 1 and 2. Pressure drop was also monitored at elevated test temperature of 353 K to quantify the effect of temperature on pressure drop (Figures 3A-ii and 3A-iv). At 353 K, experiment nos. 5 and 6 showed pressure drops of around 0.35 and 0.33 MPa for SiO 2 and clay emulsion flooding, respectively, which was performed without polymer flood (Sharma et al., 2015). The pressure drops did not decrease significantly with increasing temperature and showed almost same profile as shown for experiment nos. 1 and 2 at 313 K. The reason may be attributed to marginal decrease in the viscosity of NSP emulsion (see Section 3.2) due to the presence of nanoparticle (Sharma et al., 2014). It was observed that pressure drop slightly decreased for polymer flood injection at 353 K in experiment nos. 7 (SiO 2 ) and 8 (clay) as compared to 313 K (experiment no. 3 and 4) as shown in Figures 3A-ii and 3A-iv. It might be due to drop in the viscosity of polymer solution (see Section 3.2), which reported with a decrease in the magnitude of pressure drop as shown in Figure 3A-iv. Results on oil recoveries for core-flood experiments at 313 and 353 K are given in Table 2. Figure 3B also shows the effect of viscous polymer flood on oil recovery of these NSP emulsions at 313 and 353 K for experiment nos. 3, 4, 7, and 8. It is clear from Figure 3B and Table 2 that the use of a polymer viscous flood followed by NSP emulsion improved the rate of cumulative oil recovery by 4.71 (313 K) and 1.67% OOIP (353 K) for SiO 2 emulsion and 6.5 (313 K) and 3.45% OOIP (353 K) for clay emulsion. This might be due to polymer induced improvement in mobility ratio in core sample, which consequently reduced the extent of fingering and improved the oil recovery, which is inconsistent with the results of pressure drop (Figure 3A). From the results, it can be concluded that oil recovery and pressure drop of Pickering emulsion flooding can be increased further by incorporating a viscous flood drive for a range of reservoir temperatures. 3.4 SEM Study Nanoparticles may show plugging in small size pores of core sample due to unsuccessful penetration and need investigation (Nelson, 2009). As a consequence, the permeability of core may get reduced and so the oil recovery. Figure 4A shows SEM image of a core 1 post flooding of NSP emulsion, which shows SiO2 nanoparticles, retained in core. It is expected that the oil displacement efficiency for subsequent flooding experiments may decrease due to permeability impairment owing to retention. However, these SEM results are in agreement with our recent work where we gravimetrically calculated the permeability impairment of 15% after a fifth round of SiO 2 emulsion flooding on a single core sample (Sharma et al., 2015). Figure 4B shows the recovery of crude oil obtained after brine flood, SiO 2 emulsion flood, polymer flood, and chase water flood. Recovery of oil along with emulsion is visible with milky

8 USE OF OIL-IN-WATER PICKERING EMULSION 1601 FIGURE 3 Effect of polymer flood on (A) pressure drop and (B) production profile of NSP emulsion flooding conducted at different temperature (313 and 353 K).

9 TABLE 2 Results of core-flood tests Additional Oil Recovery,% OOIP Experiment No. (CS) ET T, K Flood scheme Water flood recovery,% OOIP After emulsion flood,% OOIP After PF,% OOIP After chase brine flood (% OOIP) Total additional oil recovery,% OOIP Cumulative oil recovery,% OOIP Remarks 1 SE 313 without PF Sharma et al., with PF This Work without PF Sharma et al., with PF This Work 2 CE 313 without PF Sharma et al., with PF This work without PF Sharma et al., with PF This Work T = temperature; OOIP: original oil in place; ET = emulsion type; SE = SiO2 emulsion; CE = clay emulsion; PF = polymer flood. 1602

10 USE OF OIL-IN-WATER PICKERING EMULSION 1603 FIGURE 4 (A) SEM micrograph showing nanoparticle retention for SiO 2 emulsion system containing 1.0 wt% SiO 2 nanoparticles, 0.22 wt% surfactant and 1000 ppm polymer at 298 K; (B) production of crude oil during (a) water flooding (2 PV); (b) SiO 2 emulsion flooding (0.5 PV); (c) polymer flooding (0.5 PV); and (d) chase water flooding (2 PV) for experiment no. 3 at 313 K. emulsion phase. This indicates that these emulsions stayed in the core channels during the 0.5 PV emulsion injection to mobilize the residual oil by changing its properties, and thereafter received along with the chase water flood at the outlet end of the core. The recovery of emulsion at the end of chase water flood also indicates the possibility of recovery of these emulsions back at the surface, and with suitable processing can be reinjected into the reservoir for efficient and economic EOR process. 4. CONCLUSION This study shows the efficacy of a viscous polymer flood on incremental oil recovery of emulsion flood system stabilized by SiO 2 and clay nanoparticles in the presence of surfactant and polymer. The results showed significant growth in cumulative oil recovery by 4.71% and 6.5% OOIP of SiO 2

11 1604 T. SHARMA ET AL. and clay emulsion flooding conducted at 13.6 MPa and 313 K. It was observed that the injection of polymer flood helped in sustaining pressure drop at higher values, which resulted significant increase in cumulative oil recoveries by 1 6% OOIP for both the Pickering emulsions at different test temperatures (313 and 353 K). From the results, it can be concluded that the use of a viscous polymer flood increased oil recovery and pressure drop of Pickering emulsion flooding. Subsequent use of SiO 2 Pickering emulsion showed plugging of core sample due to nanoparticle retention as evidenced by SEM study. FUNDING Tushar Sharma gratefully acknowledges the laboratory support from the Pandit Deendayal Petroleum University, Gujarat, India, and Indian Institute of Technology Madras, Chennai. REFERENCES Hematpour, H., Mardi, M., Edalatkhah, S., and Arabjamaloei, R. (2011). Experimental study of polymer flooding in lowviscosity oil using one-quarter five-spot glass micromodel. Pet. Sci. Technol. 29: Hermansen, H., Landa, G. H., Sylte, J. E., and Thomas, L. K. (2000). Experiences after 10 years of water flooding the Ekofisk Field, Norway. J. Pet. Sci. Eng. 26: Lee, K. S. (2010). Effects of polymer adsorption on the oil recovery during polymer flooding processes. Pet. Sci. Technol. 28: Nelson, P. H. (2009). Pore-throat sizes in sandstones, tight sandstones, and shales. AAPG Bull. 93: Pei, H., Zhang, G., Ge, J., Tang, M., and Zheng, Y. (2012). Comparative effectiveness of alkaline flooding and alkalinesurfactant flooding for improved heavy-oil recovery. Energy Fuels 26: Ponmani, S., William, J. K. M., Samuel, R., Nagarajan, R., and Sangwai, J. S. (2014). Formation and characterization of thermal and electrical properties of CuO and ZnO nanofluids in xanthan gum. Colloids Surf. A 443: Sarma, H. K., Maini, B. B., and Jha, K. (1998). Evaluation of emulsified solvent flooding for heavy oil recovery. J. Can. Pet. Technol. 37: Sharma, T., Kumar, G. S., Chon, B. H., and Sangwai, J. S. (2014). Thermal stability of oil-in-water Pickering emulsion in the presence of nanoparticle, surfactant and polymer. J. Ind. Eng. Chem. 22: Sharma, T., Kumar, G. S., and Sangwai, J. S. (2015). Comparative effectiveness of production performance of Pickering emulsion stabilized by nanoparticle surfactant polymer over surfactant polymer (SP) flooding for enhanced oil recovery for Brownfield reservoir. J. Pet. Sci. Eng. 129: Zhang, T., Davidson, A., Bryant, S. L., and Huh, C. (2010). Nanoparticle-stabilized emulsions for applications in enhanced oil recovery. SPE MS, SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April